Field of the Invention
The present inventions relate to the delivery of high power directed energy for use in well control systems.
As used herein, unless specified otherwise “high power laser energy” means a laser beam having at least about 1 kW (kilowatt) of power. As used herein, unless specified otherwise “great distances” means at least about 500 m (meter). As used herein, unless specified otherwise, the term “substantial loss of power,” “substantial power loss” and similar such phrases, mean a loss of power of more than about 3.0 dB/km (decibel/kilometer) for a selected wavelength. As used herein the term “substantial power transmission” means at least about 50% transmittance.
As used herein the term “earth” should be given its broadest possible meaning, and includes, the ground, all natural materials, such as rocks, and artificial materials, such as concrete, that are or may be found in the ground, including without limitation rock layer formations, such as, granite, basalt, sandstone, dolomite, sand, salt, limestone, rhyolite, quartzite and shale rock.
As used herein the term “borehole” should be given it broadest possible meaning and includes any opening that is created in a material, a work piece, a surface, the earth, a structure (e.g., building, protected military installation, nuclear plant, offshore platform, or ship), or in a structure in the ground, (e.g., foundation, roadway, airstrip, cave or subterranean structure) that is substantially longer than it is wide, such as a well, a well bore, a well hole, a micro hole, slimhole and other terms commonly used or known in the arts to define these types of narrow long passages. Wells would further include exploratory, production, abandoned, reentered, reworked, and injection wells.
As used herein the term “drill pipe” is to be given its broadest possible meaning and includes all forms of pipe used for drilling activities; and refers to a single section or piece of pipe. As used herein the terms “stand of drill pipe,” “drill pipe stand,” “stand of pipe,” “stand” and similar type terms should be given their broadest possible meaning and include two, three or four sections of drill pipe that have been connected, e.g., joined together, typically by joints having threaded connections. As used herein the terms “drill string,” “string,” “string of drill pipe,” string of pipe” and similar type terms should be given their broadest definition and would include a stand or stands joined together for the purpose of being employed in a borehole. Thus, a drill string could include many stands and many hundreds of sections of drill pipe.
As used herein the term “tubular” is to be given its broadest possible meaning and includes drill pipe, casing, riser, coiled tube, composite tube, vacuum insulated tubing (“VIT), production tubing and any similar structures having at least one channel therein that are, or could be used, in the drilling industry. As used herein the term “joint” is to be given its broadest possible meaning and includes all types of devices, systems, methods, structures and components used to connect tubulars together, such as for example, threaded pipe joints and bolted flanges. For drill pipe joints, the joint section typically has a thicker wall than the rest of the drill pipe. As used herein the thickness of the wall of tubular is the thickness of the material between the internal diameter of the tubular and the external diameter of the tubular.
As used herein, unless specified otherwise the terms “blowout preventer,” “BOP,” and “BOP stack” should be given their broadest possible meaning, and include: (i) devices positioned at or near the borehole surface, e.g., the surface of the earth including dry land or the seafloor, which are used to contain or manage pressures or flows associated with a borehole; (ii) devices for containing or managing pressures or flows in a borehole that are associated with a subsea riser or a connector; (iii) devices having any number and combination of gates, valves or elastomeric packers for controlling or managing borehole pressures or flows; (iv) a subsea BOP stack, which stack could contain, for example, ram shears, pipe rams, blind rams and annular preventers; and, (v) other such similar combinations and assemblies of flow and pressure management devices to control borehole pressures, flows or both and, in particular, to control or manage emergency flow or pressure situations.
As used herein, unless specified otherwise “offshore” and “offshore drilling activities” and similar such terms are used in their broadest sense and would include drilling activities on, or in, any body of water, whether fresh or salt water, whether manmade or naturally occurring, such as for example rivers, lakes, canals, inland seas, oceans, seas, bays and gulfs, such as the Gulf of Mexico. As used herein, unless specified otherwise the term “offshore drilling rig” is to be given its broadest possible meaning and would include fixed towers, tenders, platforms, barges, jack-ups, floating platforms, drill ships, dynamically positioned drill ships, semi-submersibles and dynamically positioned semi-submersibles. As used herein, unless specified otherwise the term “seafloor” is to be given its broadest possible meaning and would include any surface of the earth that lies under, or is at the bottom of, any body of water, whether fresh or salt water, whether manmade or naturally occurring.
As used herein, unless specified otherwise the term “fixed platform,” would include any structure that has at least a portion of its weight supported by the seafloor. Fixed platforms would include structures such as: free-standing caissons, well-protector jackets, pylons, braced caissons, piled-jackets, skirted piled-jackets, compliant towers, gravity structures, gravity based structures, skirted gravity structures, concrete gravity structures, concrete deep water structures and other combinations and variations of these. Fixed platforms extend from at or below the seafloor to and above the surface of the body of water, e.g., sea level. Deck structures are positioned above the surface of the body of water a top of vertical support members that extend down in to the water to the seafloor.
Discussion of Related Art
Deep Water Drilling
Offshore hydrocarbon exploration and production has been moving to deeper and deeper waters. Today drilling activities at depths of 5000 ft, 10,000 ft and even greater depths are contemplated and carried out. For example, its has been reported by RIGZONE, www.rigzone.com, that there are over 330 rigs rated for drilling in water depths greater than 600 ft (feet), and of those rigs there are over 190 rigs rated for drilling in water depths greater than 5,000 ft, and of those rigs over 90 of them are rated for drilling in water depths of 10,000 ft. When drilling at these deep, very-deep and ultra-deep depths the drilling equipment is subject to the extreme conditions found in the depths of the ocean, including great pressures and low temperatures at the seafloor.
Further, these deep water drilling rigs are capable of advancing boreholes that can be 10,000 ft, 20,000 ft, 30,000 ft and even deeper below the sea floor. As such, the drilling equipment, such as drill pipe, casing, risers, and the BOP are subject to substantial forces and extreme conditions. To address these forces and conditions drilling equipment, for example, risers, drill pipe and drill strings, are designed to be stronger, more rugged, and in may cases heavier. Additionally, the metals that are used to make drill pipe and casing have become more ductile.
Typically, and by way of general illustration, in drilling a subsea well an initial borehole is made into the seabed and then subsequent and smaller diameter boreholes are drilled to extend the overall depth of the borehole. Thus, as the overall borehole gets deeper its diameter becomes smaller; resulting in what can be envisioned as a telescoping assembly of holes with the largest diameter hole being at the top of the borehole closest to the surface of the earth.
Thus, by way of example, the starting phases of a subsea drill process may be explained in general as follows. Once the drilling rig is positioned on the surface of the water over the area where drilling is to take place, an initial borehole is made by drilling a 36″ hole in the earth to a depth of about 200-300 ft. below the seafloor. A 30″ casing is inserted into this initial borehole. This 30″ casing may also be called a conductor. The 30″ conductor may or may not be cemented into place. During this drilling operation a riser is generally not used and the cuttings from the borehole, e.g., the earth and other material removed from the borehole by the drilling activity, are returned to the seafloor. Next, a 26″ diameter borehole is drilled within the 30″ casing, extending the depth of the borehole to about 1,000-1,500 ft. This drilling operation may also be conducted without using a riser. A 20″ casing is then inserted into the 30″ conductor and 26″ borehole. This 20″ casing is cemented into place. The 20″ casing has a wellhead secured to it. (In other operations an additional smaller diameter borehole may be drilled, and a smaller diameter casing inserted into that borehole with the wellhead being secured to that smaller diameter casing.) A blowout preventer (“BOP”) is then secured to a riser and lowered by the riser to the sea floor; where the BOP is secured to the wellhead. From this point forward, in general, all drilling activity in the borehole takes place through the riser and the BOP.
The BOP, along with other equipment and procedures, is used to control and manage pressures and flows in a well. In general, a BOP is a stack of several mechanical devices that have a connected inner cavity extending through these devices. BOP's can have cavities, e.g., bore diameters ranging from about 4⅙″ to 26¾.″ Tubulars are advanced from the offshore drilling rig down the riser, through the BOP cavity and into the borehole. Returns, e.g., drilling mud and cuttings, are removed from the borehole and transmitted through the BOP cavity, up the riser, and to the offshore drilling rig. The BOP stack typically has an annular preventer, which is an expandable packer that functions like a giant sphincter muscle around a tubular. Some annular preventers may also be used or capable of sealing off the cavity when a tubular is not present. When activated, this packer seals against a tubular that is in the BOP cavity, preventing material from flowing through the annulus formed between the outside diameter of the tubular and the wall of the BOP cavity. The BOP stack also typically has ram preventers. As used herein, unless specified otherwise, the terms “ram preventer” and “ram” are to be given its broadest definition and would include any mechanical devices that clamp, grab, hold, cut, sever, crush, or combinations thereof, a tubular within a BOP stack, such as shear rams, blind rams, blind-shear rams, pipe rams, variable rams, variable pipe rams, casing shear rams, and preventers such as Hydril's HYDRIL PRESSURE CONTROL COMPACT Ram, Hydril Pressure Control Conventional Ram, HYDRIL PRESSURE CONTROL QUICK-LOG, and HYDRIL PRESSURE CONTROL SENTRY Workover, SHAFFER ram preventers, and ram preventers made by Cameron.
Thus, the BOP stack typically has a pipe ram preventer and my have more than one of these. Pipe ram preventers typically are two half-circle like clamping devices that are driven against the outside diameter of a tubular that is in the BOP cavity. Pipe ram preventers can be viewed as two giant hands that clamp against the tubular and seal-off the annulus between the tubular and the BOP cavity wall. Blind ram preventers may also be contained in the BOP stack, these rams can seal the cavity when no tubulars are present.
Pipe ram preventers and annular preventers typically can only seal the annulus between a tubular in the BOP and the BOP cavity; they cannot seal-off the tubular. Thus, in emergency situations, e.g., when a “kick” (a sudden influx of gas, fluid, or pressure into the borehole) occurs, or if a potential blowout situations arises, flows from high downhole pressures can come back up through the inside of the tubular, the annulus between the tubular and riser, and up the riser to the drilling rig. Additionally, in emergency situations, the pipe ram and annular preventers may not be able to form a strong enough seal around the tubular to prevent flow through the annulus between the tubular and the BOP cavity. Thus, BOP stacks include a mechanical shear ram assembly. Mechanical shear rams are typically the last line of defense for emergency situations, e.g., kicks or potential blowouts. (As used herein, unless specified otherwise, the term “shear ram” would include blind shear rams, shear sealing rams, shear seal rams, shear rams and any ram that is intended to, or capable of, cutting or shearing a tubular.) Mechanical shear rams function like giant gate valves that supposed to quickly close across the BOP cavity to seal it. They are intended to cut through any tubular that is in the BOP cavity that would potentially block the shear ram from completely sealing the BOP cavity.
BOP stacks can have many varied configurations, which are dependent upon the conditions and hazards that are expected during deployment and use. These components could include, for example, an annular type preventer, a rotating head, a single ram preventer with one set of rams (blind or pipe), a double ram preventer having two sets of rams, a triple ram type preventer having three sets of rams, and a spool with side outlet connections for choke and kill lines. Examples of existing configurations of these components could be: a BOP stack having a bore of 7 1/16″ and from bottom to top a single ram, a spool, a single ram, a single ram and an annular preventer and having a rated working pressure of 5,000 psi; a BOP stack having a bore of 13⅝″ and from bottom to top a spool, a single ram, a single ram, a single ram and an annular preventer and having a rated working pressure of 10,000 psi; and, a BOP stack having a bore of 18¾″ and from bottom to top, a single ram, a single ram, a single ram, a single ram, an annular preventer and an annular preventer and having a rated working pressure of 15,000 psi. (As used herein the term “preventer” in the context of a BOP stack, would include all rams, shear rams, and annular preventers, as well as, any other mechanical valve like structure used to restrict, shut-off or control the flow within a BOP bore.)
BOPs need to contain the pressures that could be present in a well, which pressures could be as great as 15,000 psi or greater. Additionally, there is a need for shear rams that are capable of quickly and reliably cutting through any tubular, including drilling collars, pipe joints, and bottom hole assemblies that might be present in the BOP when an emergency situation arises or other situation where it is desirable to cut tubulars in the BOP and seal the well. With the increasing strength, thickness and ductility of tubulars, and in particular tubulars of deep, very-deep and ultra-deep water drilling, there has been an ever increasing need for stronger, more powerful, and better shear rams. This long standing need for such shear rams, as well as, other information about the physics and engineering principles underlying existing mechanical shear rams, is set forth in: West Engineering Services, Inc., “Mini Shear Study for U.S. Minerals Management Services” (Requisition No. 2-1011-1003, December 2002); West Engineering Services, Inc., “Shear Ram Capabilities Study for U.S. Minerals Management Services” (Requisition No. 3-4025-1001, September 2004); and, Barringer & Associates Inc., “Shear Ram Blowout Preventer Forces Required” (Jun. 6, 2010, revised Aug. 8, 2010).
In an attempt to meet these ongoing and increasingly important needs, BOPs have become larger, heavier and more complicated. Thus, BOP stacks having two annular preventers, two shear rams, and six pipe rams have been suggested. These BOPs can weigh many hundreds of tons and stand 50 feet tall, or taller. The ever-increasing size and weight of BOPs presents significant problems, however, for older drilling rigs. Many of the existing offshore rigs do not have the deck space, lifting capacity, or for other reasons, the ability to handle and use these larger more complicated BOP stacks.
As used herein the term “riser” is to be given its broadest possible meaning and would include any tubular that connects a platform at, on or above the surface of a body of water, including an offshore drilling rig, a floating production storage and offloading (“FPSO”) vessel, and a floating gas storage and offloading (“FGSO”) vessel, to a structure at, on, or near the seafloor for the purposes of activities such as drilling, production, workover, service, well service, intervention and completion.
Risers, which would include marine risers, subsea risers, and drilling risers, are essentially large tubulars that connect an offshore drilling rig, vessel or platform to a borehole. Typically a riser is connected to the rig above the water level and to a BOP on the seafloor. Risers can be viewed as essentially a very large pipe, that has an inner cavity through which the tools and materials needed to drill a well are sent down from the offshore drilling rig to the borehole in the seafloor and waste material and tools are brought out of the borehole and back up to the offshore drilling rig. Thus, the riser functions like an umbilical cord connecting the offshore rig to the wellbore through potentially many thousands of feet of water.
Risers can vary in size, type and configuration. All risers have a large central or center tube that can have an outer diameters ranging from about 13⅜″ to about 24″ and can have wall thickness from about ⅝″ to ⅞″ or greater. Risers come in sections that can range in length from about 49 feet to about 90 feet, and typically for ultra deep water applications, are about 75 feet long, or longer. Thus, to have a riser extend from the rig to a BOP on the seafloor the rise sections are connected together by the rig and lowered to the seafloor.
The ends of each riser section have riser couplings that enable the large central tube of the riser sections to be connected together. The term “riser coupling” should be given its broadest possible meaning and includes various types of coupling that use mechanical means, such as, flanges, bolts, clips, bowen, lubricated, dogs, keys, threads, pins and other means of attachment known to the art or later developed by the art. Thus, by way of example riser couplings would include flange-style couplings, which use flanges and bolts; dog-style couplings, which use dogs in a box that are driven into engagement by an actuating screw; and key-style couplings, which use a key mechanism that rotates into locking engagement. An example of a flange-style coupling would be the VetcoGray HMF. An example of a dog-style coupling would be the VetcoGray MR-10E. An example of a key-style coupling would be the VetcoGray MR-6H SE
Each riser section also has external pipes associated with the large central tube. These pipes are attached to the outside of the large central tube, run down the length of the tube or riser section, and have their own connections that are associated with riser section connections. Typically, these pipes would include a choke line, kill line, booster line, hydraulic line and potentially other types of lines or cables. The choke, kill, booster and hydraulic lines can have inner diameters from about 3″ (hydraulic lines may be as small as about 2.5″) to about 6.5″ or more and wall thicknesses from about ½″ to about 1″ or more.
Situations arise where it may be necessary to disconnect the riser from the offshore drilling rig, vessel or platform. In some of these situations, e.g., drive-off of a floating rig, there may be little or no time, to properly disconnect the riser. In others situations, such as weather related situations, there may be insufficient time to pull the riser string once sufficient weather information is obtained; thus forcing a decision to potentially unnecessarily pull the riser. Thus, and particularly for deep, very deep and ultra deep water drilling there has existed a need to be able to quickly and with minimal damage disconnect a riser from an offshore drilling rig.
In offshore drilling activities critical and often times emergency situations arise. These situations can occur quickly, unexpectedly and require prompt attention and remedial actions. Although these offshore emergency situations may have similar downhole causes to onshore drilling emergency situations, the offshore activities are much more difficult and complicated to manage and control. For example, it is generally more difficult to evacuate rig personnel to a location, away from the drilling rig, in an offshore environment. Environmentally, it is also substantially more difficult to mitigate and manage the inadvertent release of hydrocarbons, such as in an oil spill, or blowout, for an offshore situation than one that occurs onshore. The drilling rig, in an offshore environment, can be many tens of thousands of feet away from the wellhead. Moreover, the offshore drilling rig is fixed to the borehole by the riser and any tubulars that may be in the borehole. Such tubulars may also interfere with, inhibit, or otherwise prevent, well control equipment from functioning properly. These tubulars and the riser can act as a conduit bringing dangerous hydrocarbons and other materials into the very center of the rig and exposing the rig and its personnel to extreme dangers.
Thus, there has long been a need for systems that can quickly and reliably address, assist in the management of, and mitigate critical and emergency offshore drilling situations. This need has grown ever more important as offshore drilling activities have moved into deeper and deeper waters. In general, it is believed that the art has attempted to address this need by relying upon heavier and larger pieces of equipment; in essence by what could be described as using brute force in an attempt to meet this need. Such brute force methods, however, have failed to meet this long-standing and important need.